The present invention relates to a method for reducing the level of sulfur oxide emissions from a catalytic hydrocarbon cracking process.
Commercial catalytic hydrocarbon cracking systems employ catalyst in a moving bed or fluidized bed. The catalyst cycles between a cracking reactor and a catalyst regeneration vessel. In a fluidized catalytic cracking (FCC) operation, a stream of hydrocarbon feed is contacted with catalyst particles in a riser reactor or reactor vessel, usually at a temperature of about 800.degree.-1100.degree. F. The reactions of hydrocarbons in the hydrocarbon stream at this temperature result in deposition of carbonaceous coke on the catalyst particles. The resulting fluid products, including hydrocarbons, hydrogen, etc., are thereafter separated from the coked catalyst and are withdrawn from the cracking zone. The coked catalyst is then typically stripped of volatiles and is passed from the reactor into a catalyst regeneration zone. In the regenerator, the coked catalyst is contacted with a fluidizing gas containing a controlled amount of molecular oxygen. The coke is burned off the catalyst to a desired low coke level and simultaneously the catalyst is heated to a high temperature required when the catalyst is returned to the reactor for cracking. After the regeneration is finished, the catalyst is returned to the cracking zone, where it is used again to vaporize the hydrocarbons and catalyze cracking. The flue gas formed by combustion of coke in the regenerator is separately removed from the regenerator. The flue gas may be treated to remove particulates and carbon monoxide from it, and is then typically passed into the atmosphere. Concern with the control of emission of pollutants in the flue gas has resulted in a search for improved methods for controlling the pollutants such as carbon monoxide and sulfur oxides.
The hydrocarbon feeds normally processed in commercial FCC units contain at least some sulfur, which is normally termed "feed sulfur". Usually, about 2-10% or more of the feed sulfur present in hydrocarbon streams processed in a given FCC unit is transferred from the feed stream to the particles of catalyst as a part of the coke deposited on the catalyst particles. Sulfur which is deposited on a catalyst is herein termed "coke sulfur". The coke sulfur is eventually passed from the reaction zone into the catalyst regenerator along with the coked catalyst. In this way, about 2-10% or more of the sulfur present in the feed is continuously passed into the catalyst regeneration zone. In the regenerator, the coke sulfur is burned, along with the carbon and hydrogen in the coke. The coke sulfur forms gaseous sulfur dioxide and sulfur trioxide. These gases are then conventionally removed from the regenerator in the flue gas.
The prior art has suggested diminishing the amount of sulfur oxides in FCC regenerator flue gas by desulfurizing the hydrocarbon feed in a separate desulfurization unit prior to undertaking the FCC operation. Another method for reducing the amount of sulfur oxides in the flue gas is by conventional flue gas desulfurization after removal of the flue gas from the FCC regenerator. These two alternatives both require elaborate extraneous equipment and energy input, and for this reason are not highly desirable ways to control the sulfur oxides. Most of the sulfur contained in the hydrocarbon feed does not become coke sulfur in the cracking reactor. Instead, it is converted either to normally gaseous sulfur compounds such as hydrogen sulfide and carbon oxysulfide or else is converted to normally liquid organic sulfur compounds. These gaseous and liquid sulfur compounds are removed from the cracking reaction zone and carried along with the vapor products which are recovered. Thus, about 90% or more of the feed sulfur is continuously removed from the cracking reactor in the stream of processed, cracked hydrocarbons. About 40-60% of the sulfur mixed with the cracked hydrocarbons is in the form of hydrogen sulfide. For this reason, it is necessary to make provisions for recovering hydrogen sulfide from the effluent from the FCC reactor. In a typical commercial operation, a very-low-molecular-weight offgas stream is separated from the C.sub.3 + liquid hydrocarbons in a gas recovery unit, and the offgas is then treated, e.g., by scrubbing it with an amine solution, to remove the hydrogen sulfide. Removal of hydrogen sulfide and other sulfur compounds from the fluid effluent from the cracking reactor is rather simple and inexpensive as compared to the methods which must be used to remove sulfur oxides from the FCC regenerator flue gas by any conventional method. Thus, if all the sulfur which is now passed into the regenerator and removed from the cracking unit as in the flue gas could be shifted into a single recovery operation already performed on the cracking reactor offgas, the use of two separate sulfur recovery operations in an FCC system could be obviated. The sulfur forming the coke sulfur could then be removed from the FCC system as simply a small addition to the large amount of sulfur in the feed which is already removed with the vapor products. The small added expense, if any, of increasing the amount of hydrogen sulfide by 5-15% is substantially less than the expense of either separate feed desulfurization or flue gas desulfurization. Reactor offgas systems in most conventional FCC units usually have the capacity to remove more hydrogen sulfide from the offgas than is now required. Thus, it is apparent that it would be desirable to direct substantially all the sulfur in the feed into a path which led to its removal from the cracking unit in the vapor cracked products stream and reduced the amount of sulfur oxides leaving the system in the regenerator flue gas.
It has been suggested, e.g., in U.S. Pat. No. 3,699,037, to lower the amount of sulfur oxides in regenerator flue gas by adding particles of Group II-A metal oxides and/or carbonates, such as dolomite, MgO or CaCO.sub.3, to the circulating catalyst in an FCC unit. The Group II-A metals react with sulfur oxides in the flue gas to form solid sulfur-containing compounds. The Group II-A metal oxides do not have sufficient physical strength to remain as particles in the unit, and regardless of the size of the particles introduced, they are rapidly reduced to fines by attrition and pass out of the FCC unit along with the catalyst fines. Thus, addition of particles of Group II-A metals is a continuous, once-through type operation, so that large amounts of these materials must be introduced on a regular basis into the unit in order to substantially reduce the level of sulfur oxides in the regenerator flue gas.
It has also been suggested, e.g., in U.S. Pat. No. 3,835,031, to lower the level of sulfur oxides in an FCC regenerator flue gas by impregnating a Group II-A metal oxide onto a conventional silica-alumina cracking catalyst. The attrition problem encountered when using unsupported Group II-A metal compounds is thereby either eliminated or reduced. Unfortunately, the Group II-A metals, such as magnesia, have an undesirable effect on the activity and selectivity of cracking catalysts. Addition of Group II-A metal compounds to cracking catalyst has two noticeably adverse effects on the results obtained in the cracking operation. First, the yield of the liquid hydrocarbon fraction recovered from the cracking operation is substantially lowered, typically by greater than 1 volume percent of the feed volume. Second, the octane rating of the gasoline or naphtha fraction (75.degree.-435.degree. boiling range) is substantially lowered. Both of the above-noted consequences are seriously detrimental to the economic viability of an FCC cracking operation. Complete removal of sulfur oxides from the regenerator flue gas would thus not compensate for the losses in yield and octane which would result from adding Group II-A metals to an FCC catalyst.
A copending U.S. patent application, Ser. No. 666,115, filed on Mar. 11, 1976 (now U.S. Pat. No. 4,071,436), discloses the use of alumina included in a particulate solid other than particulate FCC catalysts or included as a separate phase in the particulate FCC catalyst for the purpose of removing sulfur oxides from FCC regenerator flue gas. The patent application teaches that the alumina used in the operation should preferably be substantially free from silica, since the presence of silica in intimate combination with the alumina renders the alumina wholly or partially inactive for the intended use.
U.S. Pat. No. 3,953,587 describes the use of hydrogen-form and sodium-exchanged zeolites to form sulfur by treatment of a gas-containing low concentrations of hydrogen sulfide and sulfur dioxides, such as Claus-plant effluents. The reaction temperature for the sulfur formation step is 400.degree.-700.degree. F., and the zeolite material is thereafter regenerated and the sulfur recovered by heating the zeolite to 800.degree.-1000.degree. F. in an inert atmosphere to vaporize the sulfur.
U.S. Pat. No. 3,988,129 describes a process in which sulfur dioxide is adsorbed on a zeolitic crystalline aluminosilicate at a temperature of 10.degree.-50.degree. C., the sulfur dioxide is subsequently desorbed by an air stream 150.degree.-350.degree. C., and the zeolite is then cooled in air to the adsorption temperature.
Various catalysts containing vanadium, especially those containing vanadate ions, such as potassium vanadate, are well known as catalysts for the oxidation of sulfur dioxide to form sulfur trioxide.